Central processing facility, direct contact steam generation optimization

ABSTRACT

Embodiments of the present disclosure can include a system. The system can include a hydrocarbon production site. The system can include a direct contact steam generator (DCSG) system. The DCSG system can be configured to generate steam and supply the steam to an unconventional oil recovery process. The DCSG system can reside in close proximity to the hydrocarbon production site. The DCSG can include a DCSG boiler to which feedwater is provided, the feedwater being treated and supplied to the DCSG system from a remote central processing facility (CPF).

FIELD OF THE INVENTION

Embodiments of the present disclosure relate generally to a method, apparatus and system for the optimization of an unconventional oil recovery Central Processing Facility (CPF) for the cost effective and efficient implementation of a Direct Contact Steam Generation (DCSG) system which is preferably located at the well pad.

BACKGROUND AND RELATED ART

Direct Contact Steam Generators (DCSGs) are relatively new and not well accepted in steam assist gravity drain (SAGD), Steam Flood (SF) and Cyclic Steam Stimulation (CSS) heavy oil recovery. Great headway is being made in the implementation and acceptance of this technology into the SAGD world. DCSG systems, such as the Advanced Petro Technologies CEDS™ system have the possibility of revitalizing the Canadian SAGD market. It will have a positive influence on any unconventional oil recovery process that requires steam. There is much filed art relating to unconventional oil recovery and DCSG technology. There is also much already filed art specifically on CEDS™ steam generation technology. In all cases of DCSG there is a direct relationship to the efficient implementation of this new technology and the support of this technology from a CPF design. Conventional SAGD CPF's with Once Through Steam Generators (OTSGs) are huge and complex facilities. The majority of capital expenditure (Capex) and operating expenditure (Opex) related to the unconventional oil recovery process is spent at the conventional CPF. Much related art has been filed to optimize the conventional SAGD CPFs.

BRIEF SUMMARY

Various embodiments of the present disclosure can include a system. In some embodiments, the system can include a hydrocarbon production site. In some embodiments, the system can include a direct contact steam generator (DCSG) system. The DCSG system can be configured to generate steam and supply the steam to an unconventional oil recovery process. The DCSG system can reside in close proximity to the hydrocarbon production site. The DCSG system can include a DCSG boiler to which feedwater is provided, the feedwater being treated and supplied to the DCSG system from a remote central processing facility (CPF).

Various embodiments of the present disclosure can include a system. In some embodiments, the system can include a hydrocarbon production site. In some embodiments, the system can include a DCSG system. The DCSG system can be configured to generate steam and supply the steam to an unconventional oil recovery process. The DCSG system can reside in close proximity to the hydrocarbon production site. The DCSG system can include a DCSG boiler to which feedwater is provided, the feedwater being treated and supplied to the DCSG system at a location proximate to a location of the hydrocarbon production site.

Various embodiments of the present disclosure can include a system. In some embodiments, the system can include a hydrocarbon production site. In some embodiments, the system can include a DCSG system. The DCSG system can be configured to generate steam and supply the steam to an unconventional oil recovery process. The DCSG system can reside in close proximity to the hydrocarbon production site. The DCGS system can include a DCSG boiler to which feedwater is provided, the feedwater being treated and supplied to the DCSG system at a location in close proximity to a location of the hydrocarbon production site, wherein the feedwater is not treated or supplied via a central processing facility (CPF).

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 depicts a simplified schematic representation of a SAGD CPF, in accordance with embodiments of the present disclosure.

FIG. 2A depicts an example of a new CPF optimized for a DCSG well, pad, or series of pads configuration, in accordance with embodiments of the present disclosure.

FIG. 2B depicts an example of a new well, pad, or series of pads optimized for a DCSG configuration that compliments the CPF in FIG. 2A, in accordance with embodiments of the present disclosure.

FIG. 3A depicts an example of another new CPF optimized for a DCSG well, pad, or series of pads configuration, in accordance with embodiments of the present disclosure.

FIG. 3B depicts an example of another new well, pad, or series of pads optimized for a DCSG configuration that compliments the CPF in FIG. 3A, in accordance with embodiments of the present disclosure.

DETAILED DESCRIPTION

Embodiments of the present disclosure relate generally to a method, apparatus and system for the optimization of an unconventional oil recovery Central Processing Facility (CPF) for the cost effective and efficient implementation of a Direct Contact Steam Generation (DCSG) system which is preferably located at the well pad. The CPF could be configured for a Steam Assisted Gravity Drain (SAGD) unconventional oil recovery process.

Conventional SAGD CPF's are jokingly known as “a huge and expensive water treatment plant with a small oil well attached to them.” This unfortunate case is directly a result of using conventional OTSG units. These steam generation units need very clean boiler feedwater to survive. They also need the enormous and expensive support systems to generate the clean boiler feedwater. Because of these requirements, the once through steam generators are typically placed in the CPF. Unfortunately, this placement can make the steam generators miles away from the hydrocarbon wells they serve. Steam does not travel well and it loses its energy quickly when shipped through a pipe. This significantly adds to the cost of using the generated steam for unconventional oil recovery.

Steam generation capacity at a conventional CPF is typically greater than 80,000 barrels per day (bpd). This is partially due to the need to amortize through production volume the enormous cost and effort of producing acceptably clean boiler feedwater for the conventional boilers.

DCSGs are today considered unconventional boilers. They are preferably located at a hydrocarbon production site, such as a well, or pad, or at least close to a number of pads. A pad can be a collection of wells. At one of these locations, steam can be used directly or in a worst case scenario, the steam may have to travel a minimal distance. DCSGs can operate on dirty water and for the most part eliminate the “huge water treatment plant” requirement from the CPF. This new paradigm shift presents opportunities to re-think the CPF design and its function to optimize it for DCSG technology. At least 2 approaches to apply this new technology are possible. Embodiments of the present disclosure include methods, apparatus, and systems to optimize the CPF for DCSG applications. In these preferred applications the DCSGs will be placed close to the wells. In an example, a steam outlet conduit associated with the DCGSs can be less than one mile in length. In some embodiments, the steam outlet conduit associated with the DCGs can be at the hydrocarbon production site (e.g., well), effectively placing the steam outlet conduit zero feet away from the oil production site. In some embodiments, the steam outlet associated with the DCGS can be up to two miles away from the oil production site.

At this ideal location, close to the wells, the DCSG system can be configured to produce as small as 1,000 bpd of steam and can serve a single well. In some embodiments, the DCSG system can be configured to produce as large as 50,000 bpd, if the system serves a number of closely positioned pads that require high volumes of steam. One of the advantages of the embodiments of the present disclosure is that the CPF can now be located any reasonable pipe line distance away from the wells and pads. For example, the CPF can be located remotely from the hydrocarbon production site and/or the DCSG. In some embodiments, the CPF can be located a distance from the oil production site in a range from 10 miles to 100 miles, although embodiments are not so limited and the CPF can be located closer than 10 miles or further than 100 miles from the oil production site. This allows for a homologation of water and oil services and an economy of scale that could support a very large CPF. With the disclosed technology, the CPF could service over 100,000 bpd of unconventional oil which would equate to a conventional CPF that previously would have had to produce over 300,000 bpd of steam. This disclosed large CPF could be contained at one location and be third party operated by a service provider who sells the CPF services to a producer or a number of producers. This configuration would again reduce the Opex of the unconventional oil recovery process.

Steam Flood applications and Cyclic Steam Stimulation applications are similar in most respects, but are typically less demanding than SAGD. For that reason, this disclosed art will refer primarily to a SAGD application, which will cover the other simpler unconventional applications by default. In all cases, a better way of optimizing the current CPF is needed. As a result of the resources involved with the operation of the current CPF, if improvements are not made to the current CPF design, Opex and Capex associated with the current CPF design may lead to the downfall of much of the unconventional oil industry. Embodiments of the present disclosure provide a better, more cost-effective way, in terms of both Opex and Capex when implementing a CPF that is optimized for a DCSG system. When DCSG systems are coupled with this new optimized CPF technology it results in offering competitive relief to the beleaguered unconventional oil industries such as the Canadian SAGD market. In essence, by utilizing this new technology the industry will get a “new lease on life”.

FIG. 1 depicts a SAGD CPF, in accordance with embodiments of the present disclosure. The steam boiler 1 is typically an OTSG, but could also be a drum boiler or other conventional boiler design. A DCSG could also be used at the CPF in place of an OTSG at the drawn location but it could compromise the efficiency of the complete system due to steam transportation losses to the pads if located in the CPF. Steam traveling through a steam conduit 2, which is fluidly coupled with the steam boiler 1, is produced by the steam boiler 1. The steam that is transported to the pads via the steam conduit 2 is to be injected into the SAGD wells. In some cases, the wells could be over five miles away from the steam generator. Significant system energy losses, sometimes over 10%, can be suffered due to shipping the steam these long distances. A natural gas feed conduit 3 is fluidly coupled to the steam boiler 1 and can carry natural gas or natural gas plus a produced gas fuel supply to the steam boiler 1. A waste water conduit 5 contains the blow down waste water required to maintain the health of the conventional boiler. In some embodiments, a boiler feedwater (BFW) conduit 4 contains the boiler feedwater provided to the steam boiler 1 and is fluidly coupled to the steam boiler 1. The boiler feedwater is buffered in a storage tank 8, which is supplemented in its supply of clean and treated boiler feedwater from clean and treated makeup feedwater provided to the storage tank 8 via the makeup feedwater conduit 7. The feedwater is manufactured from returned produced water, which is provided from a bitumen treating and separation plant 16 to a water treatment plant 9 via a produced water conduit 19. The returned produced water, as the name implies, is water returned from the bitumen well. The dirty produced water provided to the water treatment plant 9 via the produced water conduit 19 goes through an extensive clean up and filtering process in the water treatment plant 9 that makes up the majority of the CPF. For simplicity, the water treatment plant 9 is diagrammatically shown in FIG. 1. The water treatment plant can produce waste water, lime sludge and cake, which are depicted as exiting the water treatment plant 9 via waste conduit 10. In some embodiments, the feedwater provided to the boiler 1 can be treated and supplied to the boiler at a location in close proximity to a location of the hydrocarbon production site.

Bitumen emulsion and produced gas arrive from the pad via production conduit 15. The mix is processed and separated via separation system 16, which can be made up of components such as one or more of a Free Water Knockout systems, skimmer (e.g., skim tank), and gas separation systems. The produced gas can be provided to a treatment system 18 via a produced gas conduit 17. The treatment system 18 can clean up the produced gas, which can be re-used in the boilers (e.g., steam boiler 1) and pads. As previously discussed, semi-processed produced water can be shipped to the water treatment process or “plant” as shown as water treatment plant 9.

Some diluent from diluent storage tank 20 may be injected into the bitumen separation system 16 through a first diluent conduit 21. The reduced viscosity bitumen is transported through bitumen conduit 22, which may need additional amounts of diluent added to become Dilbit or salable product, as shown in hydrocarbon storage and handling tank 24. The Dilbit or salable product can be transferred through hydrocarbon conduit 23 into the hydrocarbon storage and handling tank 24. The Dilbit or salable product can be pumped from the hydrocarbon storage and handling tank 24 via a pump 25 and finally exit via exit conduit 26 to a sales pipeline, in an example.

Electrical power is shown as power 6, which would be used to power the CPF and the pads. The source of the power 6 can be from an on-site generator and/or electrical transmission line connected to a power plant. A carbon-based fuel and blanket and lift gas can be received from the CPF via a gas conduit 13. In some embodiments, conduit 11 is used to provide a method to premix preferred amounts of well head gas into natural gas supply 12, which can be in communication with conduit 13. In some embodiments, conduit 14 can contain a non-natural gas, mixed but treated well head gas, to potentially be used as a blanket gas or other hydrocarbon recovery tool. Basic subsystems such as glycol loops and condensate systems have not been shown to aid in clarity.

FIG. 2A is an example of a new CPF optimized for a DCSG well, pad or series of pads configuration, in accordance with embodiments of the present disclosure. Similar elements, such as those depicted and discussed with respect to FIG. 1 are denoted with a “prime” symbol in FIG. 2A. For example, the produced gas treating facility 18, as depicted in FIG. 1, can include the same or similar features with respect to the produced gas treating facility 18′, as depicted in FIG. 2A. In contrast to FIG. 1, FIG. 2A depicts an embodiment that includes a minimal water treatment system 27. In some cases, the minimal water treatment system can include just a coarse filter. The source of DCSG boiler feedwater provided to the minimal water treatment system 27 via the produced water conduit 19′ could come directly from the Free water Knockout or from an additional downstream skim tank, which can be included in the separation system 16′. Neither of these devices are shown in FIG. 2A for simplicity. The lightly (e.g. minimally) treated water then travels through treated water conduit 30 into a dirty feedwater storage tank 28 and is transported through a boiler feedwater conduit 29 to the well, pad, or pads to be consumed by the DCSG. As generally referred to herein, the well, pad, and/or pads can be referred to as a hydrocarbon production site. The make-up feedwater in conduit 7′ could be fresh, dirty or contaminated water, or pond water from a bitumen mining operation.

FIG. 2B depicts an example of a new well, pad, or series of pads optimized for a DCSG configuration that compliments the CPF in FIG. 2A, in accordance with embodiments of the present disclosure. Similar elements, such as those depicted and discussed with respect to FIG. 1 are denoted with a “prime” symbol in FIG. 2B. For example, the electrical power 6, as depicted in FIG. 1 can include the same or similar features with respect to the electrical power 6′, as depicted in FIG. 2B. The electrical power 6′ can be received from the CPF. Carbon-based fuel and blanket and lift gas 13′ can be received from the CPF. A DCSG system 31 can be located at a well, pad or in close proximity to pads and the deployment of the generated steam via generated steam conduit 32. In some embodiments, the steam outlet conduit associated with the DCGs can be at the hydrocarbon production site (e.g., well), effectively placing the steam outlet conduit zero feet away from the oil production site. In some embodiments, the steam outlet associated with the DCGS can be up to two miles away from the oil production site.

Generated steam conduit 32 transfers steam generated by the DCSG system 31 to three closely positioned pads (pads not shown), although embodiments are not so limited. For example, the generated steam conduit 32 could be sized to only service one well or many wells or a single pad or many pads. The key to keeping a high efficiency and minimizing both Capex and Opex would be to minimize the steam losses by minimizing the distance the steam is required to travel through careful DCSG system 31 placement versus deploying the minimum amount of DCSG systems required to complete the desired unconventional oil recovery. A waste conduit 33 could be used to eject the waste solids from the produced water if superheat were used in the DCSG system 31 or blowdown waste conduit 34 could be used to eject blowdown if saturated steam conditions were generated in the DCSG system 31. A boiler feedwater conduit 29 delivers Boiler Feedwater from the CPF to the DCSG system 31. A production conduit 15′ carries the bitumen emulsion from the well producer back to the CPF.

FIG. 3A depicts an example of another new CPF optimized for a DCSG well, pad, or series of pads configuration, in accordance with embodiments of the present disclosure. Similar elements, such as those depicted and discussed with respect to FIG. 1 are denoted with a “double-prime” symbol in FIG. 3A. For example, the electrical power 6, as depicted in FIG. 1 can include the same or similar features with respect to the electrical power 6″, as depicted in FIG. 3A. The CPF in FIG. 3A is similar to the CPF depicted in FIG. 2A with the exception that the Bitumen Treating and Separation system (e.g., see 16′ in FIG. 2A) has been removed from the CPF and reproduced at the well, pad, or series of pads as shown in FIG. 3B. The larger CPF based separation system would most likely be reproduced with a higher quantity of smaller separation systems at the well, pad, or series of pads.

FIG. 3B depicts an example of another new well, pad, or series of pads optimized for a DCSG configuration that compliments the CPF in FIG. 3A, in accordance with embodiments of the present disclosure. In an example, FIG. 3B depicts a well, pad or series of pads that is configured to be served by the CPF in FIG. 3A. Elements denoted by power 6″, makeup feedwater conduit 7″, gas conduit 13″, production conduit 15″, separation system 16″, first diluent conduit 21″, DCSG system 31′, generated steam conduit 32′, waste conduit 33′, blowdown waste conduit 34′, serve the same functions already disclosed in the previous figures and are denoted by a “prime” symbol or a “double-prime”. As depicted, a first diluent conduit 21″ carries diluent which is provided from the CPF described in FIG. 3A. The diluent may be used to thin the bitumen in separator 16″ or added to the already separated bitumen in conduit 36. Produced gas can be transferred to the DCSG system 31′ via produced gas conduit 45. Pump 37 is used to move the Dilbit through conduit 36 to a pipeline or storage area. Separated boiler feedwater is sent in conduit 40 through boost pump 38 to coarse filter 39. The boiler feedwater is buffered in a buffer tank 41, where overflow conduit 44 and pump 43 and make-up inflow water in makeup feedwater conduit 7″ are used to maintain the correct level in buffer tank 41. For example, make-up inflow water can be introduced into buffer tank 41 via makeup feedwater conduit 7″ and/or water can be extracted from the buffer tank 41 via the overflow conduit 44 and pump 43 to control the level of water in the buffer tank 41. The make-up feedwater in conduit 7″ could be fresh, dirty or contaminated water, or pond water from a bitumen mining operation. Feedwater from tank 41 is transferred and pressurized by pump 42 into the DCSG system 31′.

Although multiple embodiments have been described above with a certain degree of particularity, those skilled in the art could make numerous alterations to the disclosed embodiments without departing from the spirit or scope of this disclosure. All directional references (e.g., upper, lower, upward, downward, left, right, leftward, rightward, top, bottom, above, below, vertical, horizontal, clockwise, and counterclockwise) are only used for identification purposes to aid the reader's understanding of the present disclosure, and do not create limitations, particularly as to the position, orientation, or use of the devices. Joinder references (e.g., affixed, attached, coupled, connected, and the like) are to be construed broadly and can include intermediate members between a connection of elements and relative movement between elements. As such, joinder references do not necessarily infer that two elements are directly connected and in fixed relationship to each other. It is intended that all matter contained in the above description or shown in the accompanying drawings shall be interpreted as illustrative only and not limiting. Changes in detail or structure can be made without departing from the spirit of the disclosure as defined in the appended claims.

Any patent, publication, or other disclosure material, in whole or in part, that is said to be incorporated by reference herein is incorporated herein only to the extent that the incorporated materials does not conflict with existing definitions, statements, or other disclosure material set forth in this disclosure. As such, and to the extent necessary, the disclosure as explicitly set forth herein supersedes any conflicting material incorporated herein by reference. Any material, or portion thereof, that is said to be incorporated by reference herein, but which conflicts with existing definitions, statements, or other disclosure material set forth herein will only be incorporated to the extent that no conflict arises between that incorporated material and the existing disclosure material. 

1. A system, comprising: a hydrocarbon production site; and a direct contact steam generator (DCSG) system, wherein: the DCSG system is configured to generate steam and supply the steam to an unconventional oil recovery process; the DCSG system resides in close proximity to the hydrocarbon production site; and the DCSG system includes a DCSG boiler to which feedwater is provided, the feedwater being treated and supplied to the DCSG system from a remote central processing facility (CPF).
 2. A system, comprising: a hydrocarbon production site; and a direct contact steam generator (DCSG) system, wherein: the DCSG system is configured to generate steam and supply the steam to an unconventional oil recovery process; the DCSG system resides in close proximity to the hydrocarbon production site; and the DCSG system includes a DCSG boiler to which feedwater is provided, the feedwater being treated and supplied to the DCSG system at a location proximate to a location of the hydrocarbon production site.
 3. A system, comprising: a hydrocarbon production site; and a direct contact steam generator (DCSG) system, wherein: the DCSG system is configured to generate steam and supply the steam to an unconventional oil recovery process; the DCSG system resides in close proximity to the hydrocarbon production site; and the DCGS system includes a DCSG boiler to which feedwater is provided, the feedwater being treated and supplied to the DCSG system at a location in close proximity to a location of the hydrocarbon production site, wherein the feedwater is not treated or supplied via a central processing facility (CPF).
 4. The system of claim 1, wherein the CPF is configured to service a quantity of wells and pads owned by more than one producer or single operating entity.
 5. The system of claim 1, wherein the CPF is not operated by a producer but instead is operated by a group selling the CPF services to a producer or multiple producers.
 6. The system as in any one of claim 1-3, wherein at least a portion of the DCSG boiler feedwater is taken from a free water knockout.
 7. The system as in any one of claim 1-3, wherein at least a portion of the DCSG boiler feedwater is taken from a skim tank disposed downstream of a free water knockout.
 8. The system as in any one of claims 1-7, wherein the DCSG boiler feedwater includes produced water and dirty makeup water.
 9. The system as in any one of claims 1-7, wherein the DCSG boiler feedwater includes produced water, dirty makeup water, and bitumen mining process pond water.
 10. The system as in any one of claims 1-9, wherein the hydrocarbon production site includes at least one of a well, a pad, and a series of pads.
 11. The system as in any one of claims 1-10, wherein the DCSG system is located a particular distance from the hydrocarbon production site, wherein the distance is in a range from zero to two miles.
 12. The system as in any one of claims 1 and 2, wherein: the system includes a remote central processing facility (CPF); and the CPF is configured to service a quantity of wells and pads owned by more than one producer or single operating entity.
 13. The system as in any one of claims 1 and 2, wherein: the system includes a remote central processing facility (CPF); and the CPF is not operated by a producer but instead is operated by a group selling the CPF services to a producer or multiple producers. 